ELECTRICITY ACT: SUBSIDIARY LEGISLATION

 

INDEX TO SUBSIDIARY LEGISLATION

Electricity (Grid Code) Regulations

Electricity Act (Commencement) Order

Electricity (Common Carrier) (Declaration) Regulations

 

ELECTRICITY (GRID CODE) REGULATIONS

 

[Section 30]

 

Arrangement of Regulations

 

   Regulation

 

   1.    Title

 

   2.    Interpretation

 

   3.    Application of Schedule

 

      SCHEDULE

SI 79 of 2013.

1.   Title

These Regulations may be cited as the Electricity (Grid Code) Regulations, 2013.

2    Interpretation

In these Regulations, unless the context otherwise requires–

"Code" means the Electricity Grid Code set out in the Schedule; and

"undertaking" has the meaning assigned to it in the Act.

3.   Application of Schedule

The provisions of the Schedule apply to undertakings in the electricity supply industry.

 

SCHEDULE

 

[Regulation 3]

 

THE ZAMBIAN GRID CODE

 

CONTENTS

Preface

1	Scope
2	Objective
3	Responsibility

1

Acronyms/Abbreviation

2Definitions

 

CHAPTER 1 – GOVERNANCE

1	Scope	638
2	Governance Structure	638
	2.1 Energy Regulation Board (ERB)	638
	2.2 Grid Code Technical Committee	638
	2.2.1 Functions of the GCTC	638
	2.2.2 Composition of GCTC	638
	2.3 Operation of the GCTC	639
	2.3.1 Schedule of Meetings	639
	2.3.2 Chair	639
	2.3.3 Procedures and Code of Conduct	639
	2.3.4 Alternate Representation	639
	2.3.5 Quorum	639
	2.3.6 Record Keeping	640
	2.3.7 Funding	640
	2.3.8 Transmission Planning Coordination Oversight	640
	2.4 The Grid Code Secretariat	640
3	Registration of Grid Code Participants	640
	3.1 Registration and De-registration	640
	3.2 Obligation of participants	640
4	Amendment Procedure	641
5	Exemption Procedure	641
	5.1 Unforeseen Circumstances	642
6	Complaint Reporting, Dispute Resolution and Appeal Mechansim	643
	6.1 Complaint Reporting	643
	6.1.1 Complaints about the operations of the Secretariat or GCTC	643
	6.1.2 Complaints between customers and service providers	643
	6.1.3 Non-Conformance Report	643
	6.2 Disputes	644
	6.2.1 Submission of a Dispute to ERB	644
7	Grid Code Compliance Audits	645

 

CHAPTER 2 – NETWORK

1	Application for Transmission Connections	646
2	Connection Conditions	646
	2.1 Generator connection conditions	646-8
	2.1.1 Protection (GCR1)	649
	2.1.2 Excitation system requirements (GCR2)	650
	2.1.3 Reactive capabilities (GCR3)	651
	2.1.4 Governing (GCR4)	651
	2.1.5 Black starting (GCR5)	652
	2.1.6 Emergency unit capabilities (GCR6)	652
	2.1.7 Facility for independent generator action (GCR7)	652
	2.1.8 Testing and compliance monitoring	653
	2.1.9 Non-compliance suspected by the SO	653
	2.1.10 Unit modifications	654
	2.1.11 Equipment requirements	654
	2.2 Distributors and end-use customers	654
	2.2.1 Power factor	654
	2.2.2 Protection	655
	2.2.3 Fault levels	655
	2.2.4 Network Performance	655
	2.2.5 Equipment requirements	655
	2.2.6 Additional Reinforcement	655
3	TNSP Technical Design Requirements	656
	3.1 Equipment design standards	656
	3.2 Clearances	656
	3.3 CT and VT ratios and cores	656
	3.4 Standard busbar arrangements and security criteria	656
	3.5 Motorised Isolators	656
	3.6 Earthing and Surge Protection	656
	3.6.1 Earthing isolators	657
	3.7 Tele-control	657
	3.8 Substation drawings	657
	3.9 Recorders	657
	3.10 Fault Levels	658
	3.11 The TNSP's delivered QOS	658
4	Service Provider Protection Requirements	658
	4.1 Equipment protection requirements	658
	4.1.1 Feeder protection: above 132kV	658
	4.1.2 Feeder protection: 66kV and below, at TNSP substations	659
	4.1.3 Tele-protection requirements	659
	4.1.4 Transformer and reactor protection	659
	4.1.6 Transmission bus coupler and bus section protection	660
	4.1 .7 Transmission shunt capacitor protection	660
	4.1.8 Over-voltage protection	660
	4.1.9 Ancillary protection functions	660
	4.2 System protection requirements	661
	4.2.1 Under-frequency load shedding	661
	4.2.2 Out-of-step tripping	66)
	4.2.3 Under-voltage load shedding	661
	4.3 Protection system performance monitoring	661
5	Nomenclature	662
6	TS Planning and Development	662
	6.1 Planning process	662
	6.2 Forecasting the demand	662
	6.3 Technical limits and targets for planning purposes	662
	6.3.1 Voltage limits and targets	662
	6.3.2 Other targets for planning purposes	662
	6.3.3 Reliability criteria for planning purposes	663
	6.3.4 Contingency criteria for planning purposes	663
	6.3.5 Integration of Power Stations	664
	6.3.6 Least economic cost criteria	664
	6.3.7 Cost reduction investments	665
	6.3.8 Statutory or strategic investments	665
	6.4 Development investigation reports	665
	6.5 Transmission investment plan	666
	6.6 Mitigation of network constraints	666
	6.7 Interfacing between participants and TNS Ps	666
	6.8 Special end use customer requirements for increased reliability	666
7	Network Maintenance	666

 

CHAPTER 3 – METERING

1	Objective	667
2	Scope	667
3	General Provisions	667
4	Responsibility for Metering Installations	667
5	Metering Installation Requirements	668
6	Data Validation	668
7	Meter Verification	669
8	Metering Database	669
9	Metering Database Inaccuracies	669
10	Access to Metering Data	669
11	Confidentiality	669

 

CHAPTER 4 – SYSTEM OPERATION

1	Objective	670
2	Scope	670
3	Responsibility	670
4	So Responsibilites	670
	4.1 System reliability, safety and security	670
	4.2.2 Operational measures	671
5	Scheduling of Generation and Ancillary Services	671
6	Ancillary Services	671
7	Operational Authority	671
8	Operating Procedures	672
9	Operational Liaison	672
10	Emergency And Contingency Planning	672
11	System Frequency and Ace Control Under Abnormal Frequency or Imbalance Conditions	673
	11.1 Description of normal frequency or balancing conditions	673
	11.2 Operation during abnormal conditions	673
12	Independent Action by Participants	673
13	Voltage Control	674
14	Fault Reporting, Analysis and Incident Investigation	674
	14.1 Generators, TNSPs, Distributors and End-use Customers	674
	14.2 System Operator	674
	14 .3 Regional Operator	674
	14.4 Root Cause and Forensic Analysis	675
15	Commissioning	675
16	Maintenance Coordination/Outage Planning	676
	16.1 Outage Management	676
	16.1.1 Yearly Planned Maintenance Schedule	676
	16.1.2 Yearly Unplanned Outages	676
	16.1.3 Effecting of Outages	676
	16.2 Emergency Outage	676
	16.3 Long Term Maintenance Planning for Generators	676
	16.4 Refusal/cancellation of outages	677
17	Communication Of System Conditions, Operational Information and IPS Performance	677
18	Tele-Control	677

 

CHAPTER 6 – INFORMATION EXCHANGE

1	Objective	678
2	Scope	678
3	Precedence	678
4	Information Exchange Interface	678
5	System Planning information	678
	5.1 Objective	678
	5.2 Information required by TNSPs	678
	5.3 Information required by Customers	679
	5.4 Information required by Generators	679
	5.5 Information required by the SO	679
6	Operational Information	679
	6.1 Pre-commissioning studies	679
	6.2 Genera] information requirements	679
	6.3 Commissioning and notification	680
	6.4 Inter control centre communication	680
	6.4.1 Normal Conditions	680
	6.4.2 Abnormal Conditions	681-2
7	Post-Dispatch Information	683
	7.1 System information	683
	7.2 Generation information settlement	683
	7.3 Additional post-dispatch information	683
	7.4 Half-hourly demand metering data	683
8	File Transfers	683
9	Performance Data	683
	9.1 Generator performance data	683
	9.2 Distributor and end-use customers performance	683
	9.3 TNSP and SO performance	684
	9.4 System Operation Performance Information	684
	9.4.1 Daily	684
	9.4.2 Monthly	684
	9.4.3 Annually	684
10	Confidentiality of Information	684

 

CHAPTER 7 – APPENDICES

Appendix 1:	Amendment Request Form	685
Appendix 2:	Exemption Request Form	686
Appendix 3:	Amendment and Exemption Request Log	687
Appendix 4:	Register of Approval Exemptions	688
Appendix 5:	Log of Disputes between Participants	689
Appendix 6:	Standard Application Form for Transmission Connection	690-3
Appendix 7:	Surveying, monitoring and testing for generators	694 – 702
Appendix 8:	Transmission drawings symbol set and layout conventions	703
Appendix 9:	Technical Voltage Limits	704
Appendix 10:	Typical Load Profile	705
Appendix 11:	Load Duration Curve	706
Appendix 12:	Operation during abnormal conditions	707
Appendix 13:	Format for Preliminary Incident Report	708
Appendix 14:	Distributor and End-use Customer data	709 – 14
Appendix 15:	Generator Planning Data	715 – 19
Appendix 16:	Generator Maintenance Data	720
Appendix 17:	Information requirements for upgrading of existing connections	721
Appendix 18:	Generator HV Yard Information	722
Appendix 19:	Operational Data	723 – 32
Appendix 20:	Post-dispatch Information	733
Appendix 21:	Backup Files	734
Appendix 22:	Generator Performance Data	735 – 37
Appendix 23:	Reporting format for periodic testing of under-frequency load shedding relays	738
Appendix 24:	Performance indicators for TNSPs and SO	739
Appendix 25:	Confidentiality of Information	740 – 41
Appendix 26:	Planning Schedules	742

Scope of Code

This Code applies to all undertakings.

The elements of the industry structure for which this Code applies are as follows–

 

   (a)   an SO and the national Transmission Network Service-Provider (TNSP);

 

   (b)   a Regional Operator and independent TNSP, roles that are currently with CEC;

 

   (c)   a generation sector consisting of ZESCO-owned generators and independent generators;

 

   (d)   a distribution sector;

 

   (e)   end-use customers, buying directly from a generator or being supplied via a supplier; and

 

   (f)   international trading via the interconnectors with other countries, and in line with the SAPP rules.

Objectives

This Code shall regulate the reciprocal obligations of industry participantson the use of the TS and operation of the IPS.

The Code provides for the following–

 

   (a)   minimum technical requirements for customers connecting to the TS;

 

   (b)   minimum technical requirements for service-providers;

 

   (c)   that SO obligations defined to ensure the integrity of the IPS;

 

   (d)   that obligations of participantsdefined for the safe and efficient operation of the TS; and

 

   (e)   that relevant information is made available to and by the participants.

This Code shall–

 

      (i)   ensure that investments are made within the requirements of the Code; and

 

      (ii)   provide access, on agreed standard terms, to all parties wishing to connect to or use the TS.

This Code shall apply the principle of non-discrimination through the provision of consistent and transparent principles, criteria and procedures.

Responsibility

The ERB has the responsibility of ensuring compliance with this Code for the benefit of the electricity industry and consumers.

The Grid Code Secretariat is responsible for implementation, maintenance and revision control of this Code and shall ensure that all recipients of this Code have the latest revision of the Code.

The Grid Code Secretariat shall ensure that it has the latest copies of relevant standards that have been quoted in this Code.

 

1.   Acronyms / Abbreviations

Note: Standard SI symbols and abbreviations are used throughout the Code.

AAICG:	Annual Average Incremental Cost of Generation
AC:	Alternating Current
ACE:	Area Control Error
AGC:	Automatic Generation Control
ARC:	Auto Re-close
AVR:	Automatic Voltage Regulator
A-U/F-LS:	Automatic Under-Frequency Load Shedding
B/U:	Back-Up
BSA:	Bulk Supply Agreement
CAP EX:	Capital Expenditure
CBM:	Condition Based Maintenance
CEC:	CopperbeltEnergy Corporation
CT:	Current Transformer
DC:	Direct Current
DCF:	Discounted Cash Flow
DCS:	Distributed Control System
DEF:	Directional Earth Fault
EENS:	Expected Energy No! Served
E/F:	Earth Fault
ERB:	Energy Regulation Board
ERLF:	External Reliability Loss Factor
ESI:	Electricity Supply Industry
FACTS:	Flexible AC Transmission System
F/L:	Fault Level
GAV:	Gross Asset Value
GCR:	Grid Code Requirement
GCTC:	Grid Code Technical Committee
GPS	Global Positioning System
HV:	High Voltage
HVDC:	High Voltage Direct Current
Hz:	Hertz
IDMT:	Inverse Definite Minimum Time
IEC:	International Electro-technical Commission
IEEE:	Institute of Electrical and Electronic Engineers
IPS:	Interconnected Power System
LV:	Low Voltage
MCR:	Maximum Continuous Rating
MV:	Medium Voltage
MVA:	Mega-Volt-Ampere
MVAr:	Mega-VoIt-ampere reactive
MW:	Mega-Watt
NAV	Net Asset Value
NCR:	Non-Conformance Report
NERC:	North American Electricity Reliability Council
NPV:	Net Present Value
OEM:	Original Equipment Manufacturer
O&M:	Operation and Maintenance
OST:	Out-of-Step Tripping
O/C:	Over-Current
PCC:	Point of Common Coupling
PCLF:	Planned Capability Loss Factor
PCS:	Process Control System
PPA:	Power Purchase Agreement
Protection	Grid Protection
PSA:	Power Supply Agreement
PSB:	Power Swing Blocking
pu:	per unit
QOS:	Quality of Supply
RTU:	Remote Terminal Unit
REA:	Rural Electrification Authority No. 20 of 2003
RO:	Regional Operator
SAPP:	Southern African Power Pool
SCADA:	Supervisory Control and Data Acquisition
SCS:	Substation Control System
SFR:	Start-Up Failure Rate
SO:	System Operator
SSR:	Sub-synchronous Resonance
STATCON:	Static Condenser
SVC:	Static VAR Compensator
TCSC:	Thyristor Controlled Series Capacitor
TNSP:	Transmission Network Service-Provider
TS:	Transmission System
Tx:	Transformer
UCF:	Unit Capability Factor
UCLF:	Unplanned Capability Loss Factor
Um, Umax:	Maximum rated voltage
Un:	Nominal voltage
UPC:	Unified Power Controller
VAR:	Voltage Ampere Reactive
VT:	Voltage Transformer
ZS:	Zambian Standard

 

2.   Definitions

In this Code, unless the context otherwise requires–

"academia" means research and teaching staff of institutions of learning offering post-secondary education;

"ancillary services" means services supplied to the TS by generators, distributors or end-use customers necessary for the reliable and secure transport of power from generators to distributors and customers in order to maintain the short-term reliability of the IPS and includes–

 

   (a)   operating reserves;

 

   (b)   black start;

 

   (c)   reactive power supply; and

 

   (d)   regulation and load following;

"area control error" means the mismatch between the instantaneous demand and supply of a control area, which combines the frequency error and the tie line schedule error;

"automatic generation control" means the regulation of the power output of electric generators within a prescribed area in response to change in system frequency, tie- line loading, or the relation of these to each other, so as to maintain the scheduled system frequency or the established interchange with other areas within predetermined limits or both

"black start" means the provision of generating equipment that, following a total system collapse (black out), is able to–

 

   (a)   start without an outside electrical supply; and

 

   (b)   energise a defined portion of the TS so that it can act as a start-up supply for other capacity to be synchronised as part of a process of re-energising the TS;

"budget quotes" means a provisional invoice stating connection conditions, inclusive of financial terms;

"busbar" means an electrical conduit at a substation where lines, transformers and other equipment are connected;

"connection (connected) to the TS" means physical connection of customer equipment to the TS either directly or through a dedicated transformer provided by the TNSP;

"constrained generation" means the difference between the energy scheduled under normal operating conditions and the energy scheduled under constrained conditions at a point of connection;

"control area" means an electrical system with borders defined by points of interconnection and capable of maintaining continuous balance between the generation under its control, the consumption of electricity in the area and the scheduled interchanges with other control areas;

"control centre" means an entity responsible for the operational control of the entire or specified electricity network assets;

"customer" means an entity that contracts directly with the service-provider for the provision of transmission services. These include generators, distributors, end- use customers and suppliers;

"day" means a period of 24 consecutive hours commencing at 00:00;

"demand side managed load" means load that may be reduced (or increased) in response to a signal from the System Operator and it includes interruptible load, ripple controlled residential boilers and dual fuel boilers, but excludes under- frequencycustomer load shedding;

"demarcation point" means the point at which there is a change over in ownership from service-provider to customer.

 

   (a)   TNSP – Power Stations

The HV bushing stems of the unit step-up transformers. The protection circuits of the units and step-up transformers shall belong to the generator; all other protection circuits and equipment in the HV yard shall belong to the TNSP; and

 

   (b)   TNSP– Distributors, international tie lines and end-use customers.

The demarcation point shall be at the point where ownership changes hands;

"dependability" means the probability of not failing to operate under given conditions for a given time interval [IEC 50 – 448];

"distribution system" means an electricity network consisting of assets operated exclusively at a nominal voltage as defined in ZS387– 1: Power Quality and Reliability Standard;

"distributor" means a person or entity that owns, operates or distributes electricity through a distribution system;

"electricity" means electrical produced by physical sources of energy such as hydro-power, wind power, solar power, petroleum, coal, biomass, nuclear energy and any other source;

"electricity supply industry" means the industry in Zambia involved in generation, transmission, distribution and supply of electrical energy.

"emergency" means a situation where there is unplanned loss of generation, transmission or demand facilities that jeopardizes the ability to meet system requirements;

"emergency level generation" means extra capacity, achieved without significant additional cost, from generating units over and above their MCRs that can be supplied up to one hour without risk of damage to the plant;

"emergency outage" means an outage which occurs when plant has to be taken out of service immediately so that repairs can immediately be effected to prevent further damage or loss;

"end-use customer" means a consumer of electricity who, or which, is connected to the TS;

"expert team" means a team of experts established by the GCTC;

"firm quote" means a form of contract negotiated and signed with a customer statingfinal connection conditions, including financial terms;

"firm supply" means a supply that enjoys a level of reliability as specified in the Network Chapter;

"flicker" means a cyclic voltage fluctuation, normally between 0.1 Hz and 10Hz, that causes optical stress to humans;

"force majeure" means any of the following events that prevents any participant from executing the participants obligations laid down in the Code–

 

   (a)   any overwhelming occurrence of nature that could not reasonably have been foreseen or guarded against;

 

   (b)   war, blockade, foreign hostile acts, civil war, rebellion, revolution, insurrection, sabotage or strikes or other similar stoppages of work by employees that are not caused by unreasonable actions on the part of the participants; and

 

   (c)   any other cause beyond the control of the participants, which the affected participants may by agreements regard as force majeure;

"forced outage" means an outage that is not a planned outage;

"frequency" means the number of oscillations per second on the AC waveform;

"generator" means an entity operating a generating unit or power station;

"governing" means a mode of operation where any change in system frequency beyond the allowable frequency dead band will have an immediate effect on the unit output according to the governor droop characteristic;

"Grid Code Secretariat" means the entity responsible for the administrative functions as defined in the Governance Chapter;

"Grid Service Charge" means the operating costs of the SO to ensure safe and reliable operation of the IPS. This includes funding of the Secretariat;

"Gross Asset Value" means the total cost of an asset to the TNSPrepresenting the capital cost, cost of purchase, freight and insurance, and installation;

"Incident Report" means a formal communication of an occurrence between parties that results in disagreements;

"individual customer charge" means connection costs that are peculiar to a particular customer;

"information" means a type of knowledge represented by some data, which can be exchanged, stored or processed electronically or otherwise;

"information owner" means the party to whose system or installation the information pertains;

"Interconnected Power System" means the electrical network that has a measurable influence at transmission level, consisting of–

 

   (a)   TS;

 

   (b)   Assets connected to the TS and belonging to a TNSP;

 

   (c)   Power stations with a capacity of more than 100 KVA and networks linking such power stations to the TS;

 

   (d)   International inter-connectors; and

 

   (e)   the Control area for which the SO is responsible;

"interruptible load" means consumer load or a combination of consumer loads that can be contractually interrupted or reduced, without notice, on instruction by the System Operator;

"islanding" means the capability of generating units to settle down at nominal speed, supplying own auxiliary load after separation from the grid, at up to full load pre-trip conditions;

"load curtailment" means load reduction by customers who are willing and able to reduce their use of power within 1 hour on instructions from the SO;

"load following" means the provision of generation and load response capability, including capacity, energy, and manoeuvrability, that is dispatched by the SO to match power generation and load demand within a scheduling period;

"load reduction" means the ability to reduce customer demand by load curtailment and load shedding;

"losses" means the technical or resistive energy losses incurred on the TS;

"maximum continuous rating" means the capacity that a generating unit is rated to produce continuously under normal conditions;

"metering" means equipment used in measuring supply parameters installed at supply points;

"metering installation" means an installation that comprises an energy meter that is interrogated and has a communication link;

"month" means a calendar month comprising a period-commencing at 00:00 hours on the first day of that month;

"NERC A1 and A2 criteria" means the criteria of the NERC that an ACE must pass through zero within 10 minutes of its previous zero (A 1) and that the average ACE in each 10-minute period must be within a specified limit (A2);

"net asset value" means the value an asset has after deducting all the accumulated depreciation for that asset;

"outage" means an interruption of the flow of power to a point of supply;

"outage request" means a written notice from a distributor, generator, end-use customer or TNSP for plant to be taken out of service for planned maintenance, repairs, auditing, emergency repairs, construction, refurbishment, inspection, testing or to provide safety clearance for other activities such as servitude clearance, line crossings and underpasses;

"participant" means–

 

   (a)   a generator;

 

   (b)   an end-use customer;

 

   (c)   a distributor;

 

   (d)   a supplier;

 

   (e)   a transmission network service-provider;

 

   (f) an embedded generator;

 

   (g)   the System Operator; or

 

   (h)   a Regional Operator;

 

"party" means a current or future participant;

"planned outage" means a scheduled outage of equipment that is on a yearly maintenance schedule for any year;

"plant" means any generation unit, or switching or transformation equipment, connected to the TS;

"point of common coupling" means the electrical node, normally a busbar, in a transmissionsubstation where different feeds to customers are connected together for the first time;

"point of connection" means the electrical node in a transmissionsubstation where a customer's assets are physically connected to the TNSP's assets;

"point of supply" means a transmission substation where energy can be supplied to a distributor or end-use customer;

"power" means the rate of generating, transferring or using energy;

"power station" means one or more units at the same physical location;

"primary substation equipment" means high voltage equipment installed at a substation;

"prudent utility practice" means the standards, practices, methods and procedures that conform to safety and legal requirements which are attained by exercising a degree of skill, diligence, and foresight which would reasonably and ordinarily be expected from skilled and experienced operatives engaged in the same type of undertaking under the same or similar circumstances;

"quote" means an invoice stating connection conditions, inclusive of financial terms;

"regional operator" means an entity, subordinate to the SO and independent from other market participants responsible for short-term reliability of the IPS, which is in charge of controlling and operating part of the TS in real time;

"regulating reserve" means generation capacity or demand side managed load available to respond within 10 minutes. This reserve category reserves capacity as part of the regulation ancillary service. The purpose of this is to allow for enough capacity to contrgiAe frequency and control area tie-lines power within acceptable limits in real time.

"regulation" means the provision- of generation and load response capability, including capacity, energy and manoeuvrability, that responds to automatic control signals issued by the System Operator;

"scheduling" means a process to determine which unit or equipment will be in operation and at what loading;

"security" means the probability of not having an unwanted operation;

"sensitivity analysis" means an exercise to determine the effect of changes in given parameters on an outcome;

"service-provider" means a TNSP or the System Operator;

"stakeholders" means an entity having an interest in the ESI;

"substation" means a site at which switching and/or transformation equipment is installed;

"system frequency" means the frequency of the fundamental AC voltage as measured at selected points by the System Operator;

"system minutes" means a performance indicator for interruptions, defined in the followingequation:

St=

EI_{t* 60}

PD_t

Where–

 

   (a)   S = system minutes interrupted

 

   (b)   El = energy interrupted (MWh)

 

   (c)   PD = peak demand

 

   (d)   t = period under review

"system operator" means an entity responsible for short-term reliability of the IPS, which is in charge of controlling and operating the TS and dispatching generation or balancing the supply and demand in real time;

"transmission" means the conveyance of electricity through the TS;

"transmission equipment" means a cable, overhead line, transformer, switchgear and equipment for ancillary services used for transmission purposes:

"transmissionnetwork service-provider (TNSP)" means an entity that is licensed to own and maintain transmission equipment;

"transmission system" means part of the IPS which supplies power in bulk from power stations to distributors and other customers and includes–

 

   (a)   all transmission lines and substation equipment on the IPS where the nominal voltage is as defined in the ZS387 - 1: Power Quality and Reliability Standard; and

 

   (b)   all associated equipment at TNSP substations belonging to the TNSP;

"undertaking" means any undertaking for the generation, transmission, distribution or supply of electricity, and includes such as undertaking that generates, transmits, distributes or supplies electricity solely or mainly in the interest of a group of associated companies for the purpose of the business of those companies, whether or not any excess electricity is supplied to any other consumer who is not part of the group.

"unit" means a device used to produce electrical energy;

"unplanned outage" has the same meaning as forced outage;

"use of system charge" means a charge applied by a TNSP to enable the TNSP recover its cost of installation and maintaining its network;

"Zambian Grid Code" means this Code; and

"ZESCO" means the power company incorporated in the Republic of Zambia and having its registered office at stand number 6949, Great East Road, P O Box 33304, Lusaka- 10101-Zambia.

 

CHAPTER 1 – GOVERNANCE

 

1   Scope

This Chapter shall apply to all the aspects of this Code. In the event of any conflict with existing PPAs, BSAs and such other similar agreements, this Codeshall take precedence, save where the affected parties have been granted exemptions as provided for under this Code.

 

2   Governance Structure

Figure 1 : Grid Code: Assigned Accountabilities

Expert teams	ERB Board	ApprovaI and Governance
Grid Code Technical Committee	Strategic Review and Assessment
Drafting team	Grid Code Secretariat	Administration
Service Providers	Implementation

2.1   Energy Regulation Board (ERB)

The-ERB; established by the Energy Regulation Act, Cap 436 of the law Zambia, shall ensure the implementation of this Code.

2.2   Grid Code Technical Committee

There shall be a Grid Code Technical Committee (GCTC) constituted every two years by the ERB.

2.2.1   Functions of the GCTC– The GCTC shall have the following functions–

 

   (a)   to review and make recommendations regarding proposals to amend is Code;

 

   (b)   to make recommendations regarding exemptions to specific provisions of this Code;

 

   (c)   to appoint technical experts on specific matters related to this Code;attend to the resolution of Non-Conformance Report incidences;

 

   (d)   issue guidance in relation to this Code and its implementation, performance and interpretation when requested to do so by the participants; and

 

   (e)   consider changes to this Code arising from unforeseen circumstances.

2.2.2   Composition of GCTC– The GCTC shall be composed of representatives of all stakeholders of the ESI in Zambia as follows–

 

   (a)   one member representing the SO;

 

   (b)   one member representing the RO or ROs;

 

   (c)   two members representing TNSPs;

 

   (d)   two members representing generators;

 

   (e)   one member representing Distributors;

 

   (f)   one member representing the Electrical Engineering Academia;

 

   (g)   one member representing the Engineering Institution of Zambia Council;

 

   (h)   one member representing the Ministry responsible for energy;

 

   (i)   two members representing End-use customers; and

 

   (j)   one member representing REA.

The ERB shall make available publicly the latest list of GCTC members within 14 days of any change.

2.3   Operations of the GCTC

2.3.1   Schedule of Meetings

The GCTC shall meet at least once every three months. The calendar of meetings shall be set at the first meeting, and the Grid Code Secretariat shall be responsible for sending notices of such meetings.

2.3.2   Election of Chairperson and Vice-Chairperson

The members of the GCTC shall elect a Chairperson and a Vice-Chairperson from amongst themselves at the beginning of every year. The positions of Chairperson and Vice-Chairperson shall be elective on an annual basis. In the event that both the Chairperson and the Vice-Chairperson are unable to attend a meeting, the members present at the meeting shall elect, from among the members, an alternative chairperson for the duration of that meeting.

Representatives of the ERB, SO and Ministry responsible for energy shall not qualify for election to the position of Chairperson.

2.3.3   Procedures and Code of Conduct

The GCTC shall determine its own meeting procedures and code of conduct for its members. The procedures shall set out the timelines for the processing of amendments by the GCTC.

2.3.4   Alternate Representation

All members of the GCTC will nominate alternate representatives in writing from among their representative groups, to attend meetings at which they are unable to be present. A register of alternate members shall be maintained by the secretariat.

Alternate members will have voting rights.

2.3.5   Quorum

A quorum shall consist of seven (7) members of the GCTC. Decisions by the GCTC shall be taken by consensus means of a simple majority vote of the duly constituted GCTC except for amendments to the Governance Chapter, which shall require a two-third majority vote.

2.3.6   Record Keeping

Proceedings of the GCTC meetings shall be recorded during all meetings, and shall be kept by the Grid Code Secretariat. The SO shall appoint the secretary for the GCTC meetings.

2.3.7   Funding

The Grid Code Secretariat shall fund the administrative activities of the GCTC, on a cost-recovery basis. At the beginning of every year, the GCTC shall prepare an operating budget proposal for the following year and submit it to the Grid Code Secretariat for implementation. The secretariat shall fund the operations of the GCTC and its associated committees up to the ERB approved budget and recover the costs from Grid Service Charges.

2.3.8   Transmission Planning Coordination Oversight

The GCTC shall have the duty of overseeing the coordination of transmission network planning between the TNSPs that is required under the Network Chapter section 8.7.

2.4   The Grid Code Secretariat

The SO shall serve as the Grid Code Secretariat.

The Grid Code Secretariat shall perform the following functions–

 

   (a)   co-ordinate the activities of the GCTC;

 

   (b)   keep a register of licensed undertakings;

 

   (c)   submit amendments and exemptions to the ERB following review by the GCTC; and

 

   (d)   manage the documentation relating to this Code and disseminate information to parties.

 

3   Registration of Grid Code Participants

3.1   Registration and De-registration

The Grid Code Secretariat shall be responsible for making entries in the register of participants upon receipt of notification from the ERB of licensed undertakings. Participants shall be registered in different categories:

Generator, Embedded generator, Distributor, End-use customer and TNSPs.

An undertaking shall not have access to the TS before obtaining a licence from the ERB.

Service-providers shall ensure that distributors and end-use customers are registered as participants before entering into a contract for services with such customers.

A participant whose licence has been withdrawn by the ERB ceases to be a participant.

3.2   Obligation of participants

The provisions of this Code are binding on participants and the participants shall comply with the said provisions unless exempted.

 

4   Amendment Procedure

A party, a member of the GCTC, or the ERB, may request amendments to this Code in the form set out in Appendix 1 of this Code.

A participant or member of the GCTC proposing an amendment of this Code shall record the proposed amendments on the prescribed form.

All proposed and approved amendments shall be logged on the Request Log as shown in Appendix 3.

The Grid Code Secretariat shall forward the proposed amendment to the GCTC for the review process.

If the proposed amendment requires expert opinion, the GCTC shall determine the necessity for constituting a team of experts. The GCTC shall constitute a team of experts for the purpose of allowing expert opinion to be obtained regarding a particular proposed amendment. The team of experts so constituted shall report back to the GCTC within a specific period.

The proposer of an amendment shall attend the GCTC sessions and may attend the expert team sessions and shall be allowed to make presentations if necessary.

The GCTC or the expert team may refine the amendment or make alternative amendments to achieve the same purpose. The proposer of the amendment may or may not agree that any refined or alternative amendment achieves the proposer's original purpose.

Once the GCTC has reviewed submissions, it shall make a formal submission to the ERB through the Secretariat on all proposed amendments to the Code other than those amendments proposed by ERB or the representative of the Ministry's responsible for energy or the GCTC, where the GCTC has the right to reject them. The GCTC shall give the decision it reached on each proposal, state the impact of the proposals on the Code, and also provide the ERB with divergent views on such proposals. The GCTC shall also describe its areas of discussion, findings and any recommendations made. In particular the ERB shall be informed whether the proposer continues to support the refined or alternative amendment.

The GCTC submission to the ERB shall include the text of the proposed amended Code. The GCTC may convene a Drafting Team if the documentation of the draft amendment so demands.

The ERB shall inform the Grid Code Secretariat of the ERB's decisions regarding the proposed amendments and the Secretariat shall communicate decisions to all participants.

The ERB shall notify the Minister, in writing, of the proposed amendments approved by the ERB and the Minister may issue a statutory instrument amending the Code accordingly.

 

5   Exemption Procedure

Applications for exemption from complying with any provision of this Code may be made in the form set out in Appendix 2 of this Code for any of the following reasons–

 

   (a)   to provide for existing equipment that has not been designed with consideration of the provisions of the Code;

 

   (b)   to facilitate transition through interim arrangements;

 

   (c)   to facilitate temporary conditions necessitating exemption; or

 

   (d)   contractual obligations such as PPAs entered into prior to the coming into effect of this Code.

All proposed and approved exemptions shall be logged on the Request Log as shown in Appendix 3.

If a request requires expert opinion, the GCTC shall determine the necessity for constituting a team of experts. The GCTC shall constitute a team of experts for the purpose of allowing expert opinion to be obtained regarding a particular application, which shall report back to the GCTC within a specific period.

An applicant for exemption may attend the GCTC sessions as well as the expert team sessions and will be allowed to make written or oral presentations.

Once the GCTC has reviewed submissions, it shall make a formal submission to the ERB through the Secretariat on the application for exemption. The GCTC shall give the decision it reached on each application and also provide the ERB with divergent views on such applications.

The ERB shall inform the Secretariat of the decision reached in respect of each application and Secretariat shall communicate the decision to the respective applicants and, except where an appeal has been lodged with the Minister, participants.

Full or partial exemption from complying with certain provisions of the Code may be granted to a participant that has applied for that exemption.

The Grid Code Secretariat shall maintain a register in which shall be recorded the names of the participants who have been granted exemption under this Code, the nature of the exemption so granted and its duration. The register shall be in the form shown as appendix 4.

An applicant who is dissatisfied by the decision of the ERB not to grant the application for exemption may appeal to the Minister within thirty days from the date of being notified about the decision.

5.1   Unforeseen Circumstances

It shall be the responsibility of the SO where unforeseen circumstances arise to the extent reasonably practicable under the prevailing circumstances to promptly consult all affected participants in an effort to reach an agreement as to the appropriate or necessary action to be taken. If an agreement is reached between the relevant participants and the SO, it shall be the responsibility of the SO to promptly refer the matter, including the agreement, to the GCTC for review and to make the necessary recommendations to the ERB.

In the event of an agreement not being reached between the participants and the SO, the SO shall decide on the next course of action to be taken if the security of the Grid is in question. In such cases, all participants shall comply with all instructions issued by the SO to the extent that such instructions are consistent with the technical characteristics of the relevant participant's system under the Code. The GCTC and ERB shall superintend over the SO to ensure that no unilateral measures or actions are taken that will prejudice any participant.

For the avoidance of doubt where unforeseen circumstances occur in real time the SO shall take whatever actions it considers necessary to secure the system. Subsequently the SO shall submit details of the problem and its actions to the GCTC.

 

6   Complaint Reporting, Dispute Resolution and Appeal Mechanism

The procedure for handling disputes arising from the implementation of the Code shall be as follows–

6.1   Complaint Reporting

6.1.1   Complaints about the operations of the Secretariat or GCTC

Any complaint regarding the operations of the Secretariat or the GCTC shall firstly be addressed in writing to the Secretariat. The GCTC shall attend to such complaints at or before the next scheduled meeting. If the complaint is not resolved, the matter shall be referred to the ERB as a dispute and shall follow the procedure described in Section 6.2.

6.1.2   Complaints between customers and service providers

Complaints arising between Customers and Service Providers shall be handled in accordance with section 6.1.3 and section 6.1.4.

A customer may issue an incident report to a service-provider on becoming aware of an occurrence. The service-provider shall provide a reason for the occurrence, what has been done to address it, and, if appropriate, indicate what action it shall take to avoid such an incident in the future.

A service-provider may also issue an incident report to a customer, where the customer does not comply with necessary requirements. The customer shall provide the service-provider with reasons for the occurrence and, where appropriate, indicate the measures that will be taken to address the problem.

Service-providers shall keep a log of all incident reports received and a log of all incident reports sent to customers.

Incident reports are operational in nature and generally require action only by technical and customer-relations staff.

6.1.3   Non-Conformance Report

NCRs shall be generated to indicate problems that require GCTC's intervention.

A customer under any of the following conditions may issue an NCR after an incident report-

 

   (a)   the service-provider fails to provide the appropriate feedback to the incident report;

 

   (b)   the service-provider wilfully misrepresents the facts concerning the incident;

 

   (c)   the service-provider fails to implement the agreed preventative actions within the timeframe agreed by the parties;

 

   (d)   the number of incident reports becomes excessive in relation to historical performance; or

 

   (e)   the actions arising from an ERB mediation/arbitration process are not adhered to.

A service provider under any of the following conditions may issue an NCR after an incident report–

 

   (a)   the customer fails to provide the appropriate feedback;

 

   (b)   the customer wilfully misrepresents the facts concerning an incident;

 

   (c)   the customer fails to implement the agreed preventative actions within the time frame agreed by the parties;

 

   (d)   the number of incident reports becomes excessive in relation to historical performance; or

 

   (e)   the actions arising from an ERB mediation/arbitration process are not adhered to.

In the case where the parties agree and assign responsibilities outlined in the NCR, both parties, within an agreed time frame, shall implement remedial action. In the event of parties failing to agree within a set time frame, the provisions of section 6.2 may be invoked.

Service-providers shall report annually to the ERB on the following aspects of the procedure–

 

   (a)   the number of NCRs for each customer category; and

 

   (b)   the number of closed-out NCRs for each customer category.

Upon a report or suspicion of non-compliance the ERB may seek to–

 

   (a)   resolve the issue through negotiation;

 

   (b)   take action in terms of the procedures for handling licensing contraventions;

 

   (c)   advise the parties to consider an application for amendment; or

 

   (d)   advise the parties to consider an application for exemption.

6.2   Disputes

Disputes are unresolved complaints between parties that require intervention. A dispute may be declared when an NCR cannot be closed out in the timeframe agreed by the parties. At this stage the complaint shall be referred to the ERB.

6.2.1   Submission of a Dispute to ERB

Any party may submit a dispute to the ERB provided the required process of section 6.1 has been followed.

When a dispute is raised with the ERB, participants shall provide the following information–

 

   (a)   the full history of relevant incident reports;

 

   (b)   the detailed NCR and accompanying information that gave rise to the dispute; and

 

   (c)   a written report from each participant detailing the reason for not being able to close out the NCR.

Disputes received by the ERB shall be recorded in accordance with Appendix 5. The following shall be considered by the ERB in dealing with the dispute–

 

   (a)   the effectiveness of the incident resolution management system, that is to say, the manner in which the problem was addressed at each stage before a dispute was declared;

 

   (b)   how thoroughly the problem has been studied by both participants;

 

   (c)   what action has already been taken;

 

   (d)   the actual cost, environmental, or other impact on the parties;

 

   (e)   whether the complaint is reasonable; or

 

   (f)   whether a timeframe cannot be agreed for closing out an NCR.

The ERB may act as a mediator upon agreement of the parties. Where mediation fails the parties may refer the matter for arbitration in accordance with the Arbitration Act No. 19 of 2000.

The ERB shall continue to develop a database of precedents based on disputes resolved. These precedents shall be used in rulings on complaints or disputes. However, precedents set by any other parties in attempting to resolve an NCR shall not be binding on the ERB.

The ERB shall consider the following, among other things, during the dispute resolution process–

 

   (a)   existing and historical performance trends;

 

   (b)   reference standards;

 

   (c)   the appropriate network design or operation standards;

 

   (d)   a developing database of precedents with similar events;

 

   (e)   historical agreements between the participants;

 

   (f)   the total cost impact.

Where the outcome of any dispute resolution proceedings would require or imply an amendment to the Code, the ERB shall refer the matter of amendment to the GCTC.

 

7.    Grid Code Compliance Audits

Any participant may request the GCTC to conduct an audit of another participant relating to compliance with part of, or the entire Code. The requesting participant may not request such information in relation to a particular section of the Code within six months of a previous request made under this section in relation to the relevant section. Where the participant to be audited believes that the request is frivolous or vexatious, they may declare a dispute under section 6.2.

A request under this section shall include the following information–

 

   (a)   The nature of the request;

 

   (b)   The name of the representative appointed by the requesting participant to conduct the investigation; and

 

   (c)   The date and time or times at which the information is required.

A participant may not unreasonably withhold any relevant information requested. It shall be provided to the GCTC with such access to all relevant documentation, data and records (including computer records or systems) as is reasonably requested. Where the GCTC requests information that the participant considers confidential they shall maintain the confidentiality of that information.

The cost of such audits will be borne by the complainant if the audit reveals compliance and by the participant being audited if the audit reveals non-compliance.

 

CHAPTER 2 – NETWORK

 

1   Applications for Transmission Connections

All customers seeking connection or modification to the existing TS shall apply in writing to the TNSP.

The TNSP shall provide quotes for new connections or for upgrading existing connections, according to the ERB approved tariff methodology and within the following time frames–

Table 3 – Connection time frames

	Budget Quote	Firm Quote
Connection service (business days)	<<30	<<60
Use of network service (days)	<<15	<<30

The customers may request provisional quote information from the TNSP that shall be provided without commitment and without detailed studies.

The agreed time period for connecting end-use-customers or upgrading connections shall be negotiated between the TNSP and the end-use-customers in every instance. The TNSP shall use the standard application form as shown in Appendix 6 for the processing of applications which should be read in conjunction with information provision requirements as specified in the Information Exchange Chapter.

End-use-customers shall enter into a connection contract and a PSA with the TNSP in advance of construction of the connection facilities.

End-use-customers shall enter into a use-of-system contract with the TNSP before the commencement of energy transactions over the TS.

 

2   Connection Conditions

This section specifies the minimum technical and design requirements that parties connected to or seeking connection to the TS shall adhere to.

2.1   Generator connection conditions

This section defines minimum requirements for generators connected to the TS, which are required to comply with the code.

Generators with capacity ratings as specified in Tables 4.1 (a) and 4.1 (b) below shall be subject to GCRs.

The SO shall evaluate and specify the need for optional IPS requirements which may not have been indicated in Tables 4.1 (a) and (b). The SO shall, on request, make available the requirements pertaining to the decision.

Table 4.1 (a) – Summary of the requirements applicable to specific ratings of non-Hydro Units.

Grid Code Requirement	Units other than Hydro (MW rating)
<<20	20 to 100	101 +
GCR1	Grid Protection
	Backup Impedance	No	No	Yes
	Loss of Field	Yes	Yes	Yes
	Generator backup earth fault	Yes	Yes	Yes
	HV Breaker Fail	Yes	Yes	Yes
	HV Breaker Pole Discrepancy	Yes	Yes	Depends on System Requirements
	Unit Switch-on-to-standstill Grid Protection (achieved with controls)	Yes	Yes
	Main Grid Protection only			Depends on System Requirements
	Main Grid Protection (with self-monitoring system; or main and backup			Depends on System Requirements
	Main and Backup Protection (with self-monitoring or monitoring systems)	Yes	Yes
	Reverse Power	Yes	Yes	Yes
GCR2	Excitation system requirements	Yes	Yes	Yes
	Power System Stabilizer (To comment later)	–	–
	Limiters (pressure, temp, speed available)	Yes	Yes	Yes
GCR3	Reactive Capabilities		Yes	Yes
GCR4	Governing	Yes	Yes	Yes
GCR5	Black Starting	Yes	No	No
GRC6	Emergency unit capabilities	Yes	Yes	Yes
GCR7	Independent action for control in system island	Yes	Yes	Yes

Table 4.1 (b) – Summary of the requirements applicable to specific classes of Hydro units

Grid Code Requirement	Hydro Units (MW rating)
		<<20	20 to 100	101 +
GCR1	Protection
	Backup Impedance	No	No	Yes
Backup Impedance	Yes	Yes	Yes
	Loss of Excitation	Depends on System Requirements	Yes	Yes
	Gen transformer HV (backup) earth fault	Yes	Yes	Yes
	Gen TxHV REF protection	Yes	Yes	Yes
	HV Breaker Fail	–	Yes	Yes
	Breaker Pole Discrepancy	Yes	Yes	Yes
	Unit Switch-onto-standstill Protection		Depends on System Configuration	Depends on System Configuration
	Main Protection	Yes	Yes	The exact requirement will depend on System Configuration
	Reverse Power	Depends on System Configuration	Yes	Yes
GCR2	Excitation system requirements	Yes	Yes	Yes
GCR3	Reactive Capabilities	Depends on System Configuration	Yes	Yes
GCR4	Governing	Depends on System Requirements	Yes	Yes
GCR5	Black Starting	–	Yes	Yes
GCR6	Emergency unit capabilities	Depends on System Requirements	Depends on System Requirements	Yes
GCR7	Independent action for control in system island	–	–	Depends on System Requirements

---

---